Production of approximately 49 thousand barrels of oil equivalent per
day (MBoe/d) (26% oil, 30% natural gas liquids (NGLs), 44% gas), up
30% over 1Q 2018; of the 15 gross operated wells turned online in 1Q
2019, 12 were turned online in late March resulting in minimal new
production in the quarter;

Current production of over 53 MBoe/d(2) (or 56 MBoe/d when
adding 2.8 MBoe/d for shut in production due to offset completion
activity) with 28% being oil; 2019 development plan continues to ramp
with approximately 55 gross operated wells to be turned to first sales
in 2Q 2019 – 4Q 2019;

Completion costs per foot reduced by 40% during the quarter as
compared to 4Q 2018; record drill time of 13.7 days for a 2.5-mile
Mayes well;

Recently completed 4-well Mad Play unit, located in Canadian County,
is the first 2019 optimized density unit turned to first sales;
average 15-day per well IP rate of 1,818 Boe/d (45% oil, 21% NGLs, 34%
gas) normalized to 10,000-foot lateral with an average projected well
cost of less than $7 million per well;

Recently completed the 3-well Victory Slide pad located in Grady
County; average daily rate of 1,444 Boe/d (78% oil, 8% NGLs, 14% gas)
normalized to 10,000-foot lateral for the two Mayes wells with an
average projected well cost of approximately $7 million per well; and

The company remains focused on the evaluation of various strategic
options, following recent unsolicited indications of interest from
third parties related to the outright sale of the company or in-basin
M&A and consolidation and is in the final stages of engaging one or
more banks to assist the Company in these efforts.

“Roan is beginning to execute on its optimized strategic and operational
goals for 2019 and we remain confident in the potential of the company
and its premier asset base in the Merge play,” said Joseph A. Mills,
Roan’s Executive Chairman of the Board. “Our acreage is located in the
core of the Merge play and we expect continued performance improvements
as we optimize our full-field development practices. We remain focused
on improving our overall drilling and completion performance and
continuing to reduce development costs. Finally, we are committed to
maximizing value for our shareholders as we evaluate our strategic
options.”

1)

Please see the supplemental financial information in the table under
“Non-GAAP Financial Measures” at the end of this earnings release
for a reconciliation of the non-GAAP financial measure of Adjusted
EBITDAX to its most directly comparable GAAP financial measure

2)

Current production is as of mid-May 2019 and is adjusted to reflect
additional volumes of 3.3MBoe/d that would be realized under ethane
recovery

Operational Update

Roan’s first quarter 2019 average daily production was approximately
48.9 MBoe/d (26% oil, 30% NGLs, 44% gas), up 30% over the first quarter
of 2018. Production is currently over 53 MBoe/d when normalized for
ethane recovery.

As a reminder, production in the first quarter of 2019 exhibited a
sequential decline as a result of the halting of all completion activity
in December 2018, which limited the contribution of production from new
development wells in the first quarter. Specifically, 12 of the 15 wells
that were turned online in the first quarter of 2019 came online in late
March causing minimal new production to be accounted for in the quarter.
Additionally, NGL and natural gas pricing dynamics in January led the
company to elect to reject ethane, which negatively impacted volumes by
approximately 3.3 MBoe/d for the month.

Three Months Ended

March 31,

2019

2018

Production Data

Oil (MBbls)

1,139

1,038

Natural gas (MMcf)

11,620

8,912

Natural gas liquids (MBbls)

1,329

874

Total volumes (MBoe)

4,405

3,397

Average daily total volumes (MBoe/d)

48.9

37.7

The Company drilled 19 gross (13.1 net) operated wells (36 gross lateral
miles) and brought online 15 gross (12.0 net) operated wells during the
quarter. Several of these wells were drilled but uncompleted wells
(DUCs) from 2018 and not part of the 2019 optimized drilling program.

1Q 2019

Operated Well Data

Drilled gross wells

19

Drilled net wells

13.1

Drilled gross lateral miles

36

First sales gross wells

15

First sales net wells

12.0

Previously, the Company announced 16 fourth quarter 2018
optimally-spaced wells that had an average 90-day initial production
(IP) rate of 1,059 Boe/d (50% oil, 20% NGLs, 30% gas), normalized to a
10,000-foot lateral, with an average lateral length of approximately
7,500 feet. These wells are all being pressured managed. At 120 days,
the average IP rate on the same set of wells was 1,006 Boe/d (48% oil,
21% NGLs, 31% gas) and at 150 days, the average IP rate of the 15 wells
with 150 days of production was 999 Boe/d (47% oil, 22% NGLs, 31% gas).

Recently, the Company completed and brought online two units, the Mad
Play and the Earl, both located in Canadian County. The Mad Play unit is
the first set of drilled and completed wells of the optimized 2019
program and it is a 4-well unit, with two Mayes wells and two Woodford
wells, with 500 feet of horizontal separation between wellbores located
in west Merge. The Earl is a 6-well unit, with three Mayes wells and
three Woodford wells, with 500 to 800 feet of horizontal separation
between wellbores located in the eastern Merge. The average per well
15-day IP rates are as follows:

The 4-well Mad Play unit flowed an average 1,818 Boe/d (45% oil, 21%
NGLs, 34% gas) per well from a normalized 10,000-foot lateral (with an
actual lateral length of 6,780 feet) with an average projected well
cost to be under $7 million per well

The 6-well Earl unit flowed an average 932 Boe/d (45% oil,23% NGLs,
32% gas) per well from a normalized 10,000-foot lateral (with an
actual lateral length of 10,165 feet) with an average projected well
cost to be approximately $7 million per well

The Company also recently completed the 3-well Victory Slide pad in
Grady County with first sales on May 10th. The two Mayes wells had an
average daily rate of 1,444 Boe/d (78% oil, 8% NGLs, 14% gas) per well
from a normalized 10,000-foot lateral (with an actual lateral length of
9,900 feet). The third well is a Woodford well and is still cleaning up.
The preliminary well costs are projected to be approximately $7 million
per well.

Drill times continue to improve, and the Company drilled its fastest
2.5-mile well to date during the quarter. The Red Bullet 22-27-34-11-7
2MXH was drilled in 13.7 days, nearly 30% faster than the average drill
time for 2.5-mile Mayes wells.

During the quarter, there were major improvements on completion costs.
Completion costs per foot came down by over 40% as compared to similar
completion costs during the fourth quarter 2018, due to both service
cost reductions and frac design optimization.

Financial Update

First quarter 2019 net loss was $58.1 million, or $0.38 per share, and
adjusted net income (non-GAAP) was $14.3 million, or $0.10 per share.
First quarter 2019 Adjusted EBITDAX (non-GAAP) was $72.8 million.

See the definitions and reconciliations of adjusted net income, adjusted
net income per share, Adjusted EBITDAX and cash general and
administrative (G&A) expense presented within this release to the most
directly comparable U.S. generally accepted accounting principles (GAAP)
financial measures provided in the supporting tables or definitions at
the conclusion of this press release.

First quarter 2019 average realized prices were $53.18 per barrel of oil
(Bo), $12.18 per barrel of NGLs and $1.87 per Mcf of natural gas,
resulting in a total equivalent unhedged price of $22.37 per Boe or a
total equivalent hedged price of $23.59 per Boe.

The Company’s adjusted cash operating costs for the first quarter were
$7.06 per Boe, including production expense of $3.37 per Boe, production
tax of $1.14 per Boe and cash G&A expense (non-GAAP) of $2.55 per Boe.
Both production expense and cash G&A expense were down
quarter-over-quarter on a total dollar basis. The Company expects
production expenses to continue trending down throughout the year as the
benefit of the water disposal agreement with Blue Mountain Midstream LLC
is recognized, which began early in the second quarter of 2019.

Capital expenditures for first quarter 2019 totaled approximately $172.8
million, a $44 million reduction as compared to the fourth quarter 2018.
The Company anticipates capital expenditures to trend sequentially lower
for the remainder of the year.

As of the end of the first quarter, Roan had $2.2 million of cash on the
balance sheet and $602.6 million drawn on its revolving credit facility,
resulting in a net debt balance of $600.4 million. Roan currently has no
other outstanding debt or letters of credit. The Company had
approximately $150 million of available liquidity on the revolver as of
March 31, 2019. The Company is in the process of adding additional
liquidity to its balance sheet.

A table of the Company’s derivative contracts as of May 10, 2019 is
provided at the conclusion of this press release.

First Quarter 2019 Earnings Conference Call

Roan will host a conference call to discuss first quarter 2019 results
on Wednesday, May 15, 2019 at 10:30 a.m. ET (9:30 a.m. CT). Interested
parties may listen to the conference call via webcast on the Company’s
website at www.RoanResources.com
under the “Investor Relations” section of the site or by phone. The
Company plans to post a presentation to the website prior to the start
of the call.

A replay of the webcast will be available on the Company’s website and a
replay of the call will be available for two weeks by phone:

Replay dial-in: 800-585-8367 or 416-621-4642Conference ID: 3767979

About Roan Resources

Roan is an independent oil and natural gas company headquartered in
Oklahoma City, OK focused on the development, exploration and
acquisition of unconventional oil and natural gas reserves in the Merge,
SCOOP and STACK plays of the Anadarko Basin in Oklahoma. For more
information, please visit www.RoanResources.com,
where we routinely post announcements, updates, events, investor
information, presentations and recent news releases.

Cautionary Statements

This press release includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended.
All statements, other than statements of historical fact, are
forward-looking statements which contain our current expectations about
future results. These forward-looking statements are based on certain
assumptions and expectations made by the Company, which reflect
management’s experience, estimates and perception of historical trends,
current conditions and anticipated future developments. Such statements
are subject to a number of assumptions, risks and uncertainties, many of
which are beyond the control of the Company, which may cause actual
results to differ materially from those implied or anticipated in the
forward-looking statements. When considering these forward-looking
statements, you should keep in mind the risk factors and other
cautionary statements found in the Company’s filings with the Securities
and Exchange Commission, including its Annual Report on Form 10-K for
the year ended December 31, 2018 and any subsequently filed quarterly
reports on Form 10-Q or current reports on Form 8-K.

We caution you that these forward-looking statements are subject to
all of the risks and uncertainties, most of which are difficult to
predict and many of which are beyond our control, or incidental to the
development, production, gathering and sale of oil, natural gas and
NGLs. These risks include, but are not limited to, the expectations of
plans, strategies, objectives and growth and anticipated financial and
operational performance, the structure and timing of any transaction or
strategic alternative and whether any transaction or strategic
alternative will be completed, commodity price volatility, inflation,
lack of availability of drilling and production equipment and services,
environmental risks, drilling and other operating risks, regulatory
changes, the uncertainty inherent in estimating reserves and in
projecting future rates of production, cash flow and access to capital,
the timing of development expenditures and the other risks.

Reserve engineering is a process of estimating underground
accumulations of oil, natural gas and NGLs that cannot be measured in an
exact way. The accuracy of any reserve estimate depends on the quality
of available data, the interpretation of such data and price and cost
assumptions made by reserve engineers. In addition, the results of
drilling, testing and production activities may justify revisions of
estimates that were made previously. If significant, such revisions
would change the schedule of any further production and development
drilling. Accordingly, reserve estimates may differ significantly from
the quantities of oil, natural gas and NGLs that are ultimately
recovered.

Should one or more of the risks or uncertainties described occur, or
should underlying assumptions prove incorrect, our actual results and
plans could differ materially from those expressed in any
forward-looking statements.

All forward-looking statements, expressed or implied, included in
this release are expressly qualified in their entirety by this
cautionary statement. This cautionary statement should also be
considered in connection with any subsequent written or oral
forward-looking statements that we or persons acting on our behalf may
issue.

Except as otherwise required by applicable law, we disclaim any duty
to update any forward-looking statements, all of which are expressly
qualified by the statements in this section, to reflect events or
circumstances after the date of this release.

Financial Statements

The information in the following financial statements and tables reflect
the results of Roan Resources LLC prior to September 24, 2018 and on and
after September 24, 2018, the results of Roan Resources, Inc.

Roan Resources, Inc.

Condensed Consolidated Statements of Operations (Unaudited)

Three Months Ended

March 31,

2019

2018

(in thousands, except per share amounts)

Revenues

Oil sales

$

60,571

$

63,692

Natural gas sales

11,189

10,332

Natural gas sales – Affiliates

10,592

6,558

Natural gas liquid sales

8,338

11,939

Natural gas liquid sales – Affiliates

7,849

8,449

Loss on derivative contracts

(83,642

)

(9,614

)

Total revenues

14,897

91,356

Operating Expenses

Production expenses

14,846

8,355

Production taxes

5,039

2,386

Exploration expenses

12,488

7,850

Depreciation, depletion, amortization and accretion

41,572

21,865

General and administrative

15,825

14,020

Gain on sale of other assets

(664

)

–

Total operating expenses

89,106

54,476

Total operating (loss) income

(74,209

)

36,880

Other income (expense)

Interest expense, net

(6,744

)

(1,799

)

Net (loss) income before income taxes

(80,953

)

35,081

Income tax benefit

(22,897

)

–

Net (loss) income

$

(58,056

)

$

35,081

Earnings (loss) per share

Basic

$

(0.38

)

$

0.23

Diluted

$

(0.38

)

$

0.23

Weighted average number of shares outstanding

Basic

152,540

151,294

Diluted

152,540

151,294

Roan Resources, Inc.

Condensed Consolidated Balance Sheets (Unaudited)

March 31, 2019

December 31, 2018

(in thousands, except par value and share data)

ASSETS

Current assets

Cash and cash equivalents

$

2,189

$

6,883

Accounts receivable

Oil, natural gas and natural gas liquid sales

52,506

55,564

Affiliates

5,175

9,669

Joint interest owners and other, net

148,051

133,387

Prepaid drilling advances

23,132

28,977

Derivative contracts

14,104

82,180

Other current assets

10,179

6,655

Total current assets

255,336

323,315

Noncurrent assets

Oil and natural gas properties, successful efforts method

2,801,145

2,628,333

Accumulated depreciation, depletion, amortization and impairment

(282,541

)

(230,836

)

Oil and natural gas properties, net

2,518,604

2,397,497

Derivative contracts

4,529

20,638

Other

12,967

7,659

Total assets

$

2,791,436

$

2,749,109

LIABILITIES AND EQUITY

Current liabilities

Accounts payable

$

121,110

$

49,746

Accrued liabilities

131,403

176,494

Accounts payable and accrued liabilities – Affiliates

–

8,577

Revenue payable

95,104

97,963

Drilling advances

36,149

31,058

Derivative contracts

5,583

845

Other current liabilities

2,552

790

Total current liabilities

391,901

365,473

Noncurrent liabilities

Long-term debt

602,639

514,639

Deferred tax liabilities

333,966

356,862

Asset retirement obligations

16,967

16,058

Derivative contracts

241

141

Other

5,679

902

Total liabilities

1,351,393

1,254,075

Commitments and contingencies

Equity

Class A common stock, $0.001 par value; 800,000,000 shares
authorized; 152,539,532 shares issued and outstanding at March 31,
2019 and December 31, 2018

Excludes settlement of derivative contracts prior to their
contractual maturity for the three months ended March 31, 2018.

(2)

Excludes the effects of netting gathering, transportation, and
processing costs.

Operating Expenses

Our operating expenses reflect costs incurred in the development,
production and sale of oil, natural gas and NGLs. The following table
provides information on our operating expenses:

Three Months EndedMarch 31,

2019

2018

(in thousands, except costs per Boe)

Operating Expenses

Production expenses

$

14,846

$

8,355

Production taxes

5,039

2,386

Exploration expenses

12,488

7,850

Depreciation, depletion, amortization and accretion

41,572

21,865

General and administrative (1)

15,825

14,020

Gain on sale of other assets

(664

)

–

Total

$

89,106

$

54,476

Average Costs per Boe

Production expenses

$

3.37

$

2.46

Production taxes

1.14

0.70

Exploration expenses

2.84

2.31

Depreciation, depletion, amortization and accretion

9.44

6.44

General and administrative (1)

3.59

4.13

Gain on sale of other assets

(0.15

)

–

Total

$

20.23

$

16.04

(1)

General and administrative expenses for the three months ended
March 31, 2019 and 2018 include $3.1 million, or $0.70 per Boe,
and $2.3 million, or $0.67 per Boe, of equity-based compensation
expense, respectively. General and administrative expenses for the
three months ended March 31, 2019 includes $1.5 million, or $0.34
per Boe, of bad debt expense.

Non-GAAP Financial Measures

Adjusted Net Income and Adjusted Net Income per Share

Adjusted net income and adjusted net income per share are non-GAAP
performance measures. The Company defines adjusted net income and
adjusted net income per share as net (loss) income and net (loss) income
per share excluding non-cash gains or losses on derivatives, gains on
early terminations of derivative contracts, gain on the sale of other
assets, and exploration expenses. Management uses adjusted net income
and adjusted net income per share as an indicator of the Company's
operational trends and performance relative to other oil and natural gas
companies. Adjusted net income and adjusted net income per share should
not be considered an alternative to net income (loss), operating income,
or any other measure of financial performance presented in accordance
with GAAP or as an indicator of our operating performance.

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